Most oil and gas wells require some form of stimulation to enhance hydrocarbon flow to make or keep them economically viable. The servicing of oil and gas wells to stimulate production requires the pumping of fluids under high pressure. The fluids may be caustic and are frequently abrasive because they are laden with abrasive propants such as sharp sand, bauxite or ceramic granules.
It is well know that advances in coil tubing technology have generated an increased interest in using coil tubing during well completion, re-completion and workover procedures. Techniques have been developed over the years for pumping well fracturing fluids through coil tubing, or pumping “down the backside” around the coil tubing. Processes and equipment have also been developed for perforating casing and fracturing a production zone in a single operation, as described in Applicant's U.S. Pat. No. 6,491,098 entitled Method and Apparatus for Perforating and Stimulating Oil Wells, which issued on Dec. 10, 2002.
Although performing two or more functions in a single run down a cased wellbore is economical and desirable, there is a disadvantage with using existing techniques for performing such operations. The principal disadvantage is the height of the equipment stack that is necessary for lubricating the required tool string into the well.
FIG. 1 is a schematic diagram of a setup 10 for performing a well completion in accordance with the prior art techniques in which a long tool string (not shown), e.g. a tool string for perforating and stimulating production zones of the well in a single run, are lubricated into the cased well bore.
As schematically illustrated in FIG. 1, a wellhead generally indicated by reference numeral 12 includes a casing head 14 supported by a conductor 16. The casing head 14 supports a surface casing 18. A tubing head spool 20 is mounted to the casing head 14. The tubing head spool 20 supports a production casing 22, which extends downwardly through the production zone(s) of the well.
Mounted to a top of the tubing head spool 20 is a blowout preventer protector (BOP) 24 for controlling the well after the production casing 22 is perforated. Optionally mounted to a top of the BOP is a “frac cross” 26, also referred to as a fracturing head. The purpose of the frac cross 26 is to permit well stimulation fluids to be pumped down the backside, i.e. down production casing 22, and around a coil tubing 34.
Mounted to a top of the frac cross 26 is one or more “lubricator joints” 28. In this example three lubricator joints 28a, 28b and 28c are used. The lubricator joints house the downhole tool string (not shown), which is supported by the coil tubing string 34. A wireline BOP or a coil tubing BOP 30 is mounted to a top of the lubricator joints 28a,28b,28c. Tubing rams of the coil tubing BOP 30 seal around the coil tubing string 34 while the tool string is being run into and out of the well. A wireline grease unit (not shown) or a coil tubing injector 32 is mounted to a top of the coil tubing BOP 30. The coil tubing injector 32 is used to run the coil tubing string 34 into and out of the production casing 22 in a manner well known in the art. The coil tubing string 34 is supplied from a coil tubing spool 36, which is likewise well known in the art and may be mounted on a trailer or a truck.
As is apparent, the setup 10 shown in FIG. 1 creates an equipment stack that extends 20′-40′ from the ground. The setup 10 is in a normally assembled on the ground and hoisted into place after it is assembled. For the sake of clarity, the stays, work platforms, cranes and other equipment required to assemble, disassemble, operate, and maintain the setup 10 are not shown.
As will be understood by those skilled in the art, assembling and operating the setup 10 can be dangerous, because maintenance work must be performed on elevated work platforms high off the ground. As will be further understood, the setup 10 can also be dangerous because a great deal of mechanical bending and twisting stress is placed on the wellhead 12 and the lubricator 28 by the very high setup 10, which acts as a lever when force is applied to a top of the setup 10 by operation of the coil tubing injector or 32 or the wireline unit (not shown).
As will also be appreciated by those skilled in the art, assembling the setup 10 is expensive because heavy hoisting equipment, such as an 80-ton crane, is required to hoist the equipment to those heights. The 80-ton crane must also be connected to a top of the setup 10 and used to counter force applied to the setup 10 by operation of the coil tubing injector 32 or the wireline unit. The 80-ton crane must therefore remain on the job during the entire well stimulation process. The rental of such hoisting equipment for an extended period of time is very expensive.
There is therefore a need for a way of facilitating well completion, re-completion and workover while preserving the time and cost savings of being able to perform more than one function during a single run into a cased wellbore.